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James J. Sheng - One of the best experts on this subject based on the ideXlab platform.
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further investigation of effects of injection pressure and imbibition water on co2 huff n puff performance in liquid rich shale reservoirs
Energy & Fuels, 2018Co-Authors: James J. Sheng, Shiyuan ZhanAbstract:Shale oil production has increased rapidly in the past decades, especially in the United States, and results in a revolution in the energy landscape. However, one main problem existing in the shale reservoir development is the sharp decline of liquids production in all the hydraulically fractured wells. In recent years, CO2 huff-n-puff injection has been proved to be a potential method to enhance the oil recovery. In this study, the effects of injection pressure and imbibition water on CO2 huff-n-puff performance were further investigated. Eagle Ford core samples and Wolfcamp dead oil were used in this experimental study. The microscopic pore characteristics of Eagle Ford shale core samples were analyzed, and the results show that 98.08% of the pore sizes are distributed between 3 nm and 50 nm. The experimental results demonstrate the great potential of CO2 huff-n-puff EOR. The cumulative oil recovery can reach 68% after seven huff-n-puff cycles. The oil recovered in each cycle deceases as injection cycle...
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experimental and numerical study of permeability reduction caused by asphaltene precipitation and deposition during co2 huff and puff injection in eagle ford shale
Fuel, 2018Co-Authors: Ziqi Shen, James J. ShengAbstract:Abstract The permeability reduction associated with asphaltene precipitation and deposition in gas injection EOR processes has been widely observed and well-studied in conventional plays. In our previous research, such permeability reduction due to asphaltene deposition during gas huff and puff injection process in shale core plugs were observed. In this study, experiments were conducted to investigate the permeability reduction caused by asphaltene deposition in shale core samples during the CO 2 huff and puff injection process. A dead oil sample from a Wolfcamp shale reservoir was used. A core scale simulation model was built up to mimic the huff and puff injection process in the experiment and the parameters for the asphaltene deposition in shale were obtained by matching the experimental oil recovery and permeability reduction data. The asphaltene precipitation and deposition process during the CO2 huff and puff injection experiment are discussed in details based on the simulation results. Experimental results showed that severe permeability damage was caused by asphaltene during CO2 huff and puff injection (e.g., 48.5%), especially in the first cycle (e.g., 26.8%). Analysis of the experiments using simulation approach show that oil recovery factor reduction starts right after the beginning of CO2 huff and puff injection and the effect of asphaltene deposition on oil recovery factor accumulated during the later cycles. The asphaltene deposition was mainly formed in the near surface area of the core plug. As the CO2 concentration is quickly increased in the first cycle and more oil is near the rock surface in the first cycle, asphaltene precipitation and deposition were most significant during the huff period in the first cycle compared with the subsequent cycles. In the puff period of the first cycle, asphaltene precipitation is quickly decreased, as CO2 flow back. In addition, although oil in the inner blocks continuously flows to the outer blocks during the puff period, due to the extremely low permeability of the core plug, the amount of oil is small and this oil has already experienced the asphaltene precipitation process during the previous huff period, very small amount of increase in the asphaltene deposition occurs during the subsequent puff periods.
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investigation of asphaltene deposition mechanisms during co2 huff n puff injection in eagle ford shale
Petroleum Science and Technology, 2017Co-Authors: Ziqi Shen, James J. ShengAbstract:In this study, laboratory tests were conducted to investigate the asphaltene deposition mechanisms during CO2 huff-n-puff injection in an Eagle Ford shale core using Wolfcamp shale oil. The permeability reduction due to asphaltene deposition by mechanical plugging and adsorption mechanisms were determined using the n-Heptane and toluene reverse flooding, respectively. The results showed that 83% of the total permeability reduction is due to asphaltene deposition by mechanical plugging mechanism, while 17% of the total permeability reduction is due to asphaltene deposition by adsorption mechanism. The critical interstitial velocity for entrainment of asphaltene deposition was around 0.0008 cm/sec.
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Simulation study of huff-n-puff air injection for enhanced oil recovery in shale oil reservoirs
Petroleum, 2017Co-Authors: James J. ShengAbstract:Abstract This paper is the first attempt to evaluate huff-n-puff air injection in a shale oil reservoir using a simulation approach. Recovery mechanisms and physical processes of huff-n-puff air injection in a shale oil reservoir are investigated through investigating production performance, thermal behavior, reservoir pressure and fluid saturation features. Air flooding is used as the basic case for a comparative study. The simulation study suggests that thermal drive is the main recovery mechanism for huff-n-puff air injection in the shale oil reservoir, but not for simple air flooding. The synergic recovery mechanism of air flooding in conventional light oil reservoirs can be replicated in shale oil reservoirs by using air huff-n-puff injection strategy. Reducing huff-n-puff time is better for performing the synergic recovery mechanism of air injection. O2 diffusion plays an important role in huff-n-puff air injection in shale oil reservoirs. Pressure transmissibility as well as reservoir pressure maintenance ability in huff-n-puff air injection is more pronounced than the simple air flooding after primary depletion stage. No obvious gas override is exhibited in both air flooding and air huff-n-puff injection scenarios in shale reservoirs. Huff-n-puff air injection has great potential to develop shale oil reservoirs. The results from this work may stimulate further investigations.
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experimental study of permeability reduction and pore size distribution change due to asphaltene deposition during co2 huff and puff injection in eagle ford shale
Asia-Pacific Journal of Chemical Engineering, 2017Co-Authors: Ziqi Shen, James J. ShengAbstract:Many laboratory and simulation studies regarding gas injection enhanced oil recovery method in shale reservoir have been performed and shown good results. However, one problem not investigated is the asphaltene precipitation and deposition problem. In conventional reservoirs, the permeability reduction caused by asphaltene plugging and adsorption has been observed and well studied. In shale reservoirs, the deposition, if any, will be more critical. In this work, experimental studies were conducted to investigate the effect of asphaltene deposition on the pore size reduction and permeability reduction in shale core samples during the CO2 huff and puff injection process using a dead oil sample from a Wolfcamp shale reservoir. A decrement of pore with a diameter size in the range from 100 to 800 nm and an increment of pore with a diameter size smaller than 100 nm were observed after 6 cycles of CO2 huff and puff injection. The result indicates the existence of pore plugging and asphaltene adsorption during the gas injection process. The experimental results also showed a 47.5-nD permeability reduction after 6 cycles of CO2 huff and puff injection. Compared with the original permeability of the shale core, 126 nD, the permeability reduction is more than one-third of the original permeability. © 2017 Curtin University of Technology and John Wiley & Sons, Ltd.
Fanhua Zeng - One of the best experts on this subject based on the ideXlab platform.
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feasibility study of co2 huff n puff process to enhance heavy oil recovery via long core experiments
Applied Energy, 2019Co-Authors: Xiang Zhou, Liehui Zhang, Qingwang Yuan, Zhenhua Rui, Hanyi Wang, Jianwei Feng, Fanhua ZengAbstract:Abstract In order to study a potential way to store CO2 and enhance heavy oil production performance, five experiments are implemented on the CO2 huff 'n' puff process using long cores. The production profiles of the CO2 huff 'n' puff process are analyzed, including pressure, heavy oil recovery factor, gas production, cumulative gas oil ratio, and pressure difference. The pressure drops indicate the CO2 diffusion in heavy oil. The pressure drop in the first cycle is much lower than those in the subsequent cycles. The heavy oil recovery factor is higher than 32.75% and can reach as high as 38.02% under the pressure depletion rate of 1 kPa/min. A main trend observed for each test is that the heavy oil recovery factor decreases with increases in the cycle number. With oil production, a growing space is available for CO2 injection in the core, resulting in a higher volume of injected CO2 together with increasing gas production and a cumulative gas oil ratio. With less heavy oil production, the pressure difference between the end port and the production port decreases with the cycle number increases. A novel equation is developed to study the relationship between CO2 production and heavy oil production, and the agreement between the equation and the experimental data is extremely high ( R 2 > 0.97 ). This novel equation can be applied to predict the production performance in the later production period in the same cycle and/or to predict the performance in the subsequent cycles. Via the analyzation of the production performance of the CO2 huff 'n' puff process in heavy oil under different pressure depletion rates and different soaking times, the effect parameters, including pressure depletion rates, soaking time and cycle numbers, are optimized in this study. The optimized pressure depletion rates, soaking time, and cycle numbers are 1 kPa/min, 5 h and 3 cycles, respectively. The optimized parameters gained in the tests were upscaled using the scaling criteria, and the upscaled parameters can be applied in the field pilot test to enhance heavy oil recovery using the CO2 huff 'n' puff process.
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a critical review of the co2 huff n puff process for enhanced heavy oil recovery
Fuel, 2018Co-Authors: Xiang Zhou, Fanhua Zeng, Qingwang Yuan, Xiaolong Peng, Liehui ZhangAbstract:Abstract Heavy oil resources have become increasingly important in recent years due to a reduction in light oil production and an increase in energy consumption. A large number of heavy oil reserves are found all over the world, and traditional production methods, such as solution gas drive, water flooding, etc., cannot gain a high heavy oil recovery factor, because of the high viscosity of the heavy oil. Although the thermal method has proven efficient and economical to produce heavy oil, it cannot be applied in deep reservoirs or reservoirs with thin pay zones due to the huge heat loss in these reservoirs. Thus, in order to enhance heavy oil production, several CO 2 injection processes are applied in heavy oil reservoirs. Among them, the CO 2 huff ‘n’ puff method has proven the most applicable. In this research, the CO 2 huff ‘n’ puff process is reviewed in detail. Among the mechanisms of the CO 2 huff ‘n’ puff process in enhancing heavy oil production, the formation of foamy oil, viscosity reduction, and oil swelling are the most important ones, so that effect of foamy oil in the production stage is studied, and the viscosity reduction ratio with CO 2 injection and oil swelling factors at different temperatures and pressures are summarized. In addition, the diffusion coefficient, which indicates the mass transfer rate and amount of CO 2 dissolved into heavy oil through the two-phase interface of CO 2 and heavy oil, is analyzed in various heavy oil reservoirs at different temperatures and pressures. Experimental studies on the CO 2 huff ‘n’ puff process indicate that the process applied in the heavy oil reservoir is successful and can be carried out with an oil viscosity up to 28,646 mPa·s and a reservoir permeability up to 24,200 mD. In pilot tests in the field, economical CO 2 huff ‘n’ puff processes have been applied in the heavy oil reservoirs with an oil gravity as low as 4 °API, a reservoir depth as high as 1985 m, and a pay zone as low as 12.2 m. Specifically, CO 2 utilization can be as low as 4.2 Mscf/Stb. Numerical simulation studies can gain very good simulation results on both experimental and pilot tests studies. However, mathematical models have seldom been published on CO 2 huff ‘n’ puff processes in heavy oil reservoirs.
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enhanced light oil recovery from tight formations through co2 huff n puff processes
Fuel, 2015Co-Authors: Xiangzeng Wang, Fanhua Zeng, Ruimin Gao, Chunxia Huang, Paitoon Tontiwachwuthikul, Zhiwu LiangAbstract:Abstract The major objective of this paper was to evaluate the viability of CO2 huff ‘n’ puff processes as primary means to enhance oil recovery in low-pressure tight reservoirs and thereby optimize the corresponding key operating parameters of the process. In this study, CO2 huff ‘n’ puff corefloods were conducted by using a 973 mm-long composite core with an average porosity of 9.6% and an average permeability of 2.3 mD. The effects of primary parameters, such as slug size, injection rate, and the maximum and minimum pressures during production, chasing gas (N2) and soaking time on the performance of the process were investigated and operating strategies were optimized to lead to successful field applications. The experimental results indicate that 0.1 reservoir pore volume (PV) seems to be an optimal slug size for the first cycle, with the cycle recovery factor (RF) up to 14.52% when reservoir pressure is depleted from the maximum pressure to 8 MPa. RF is suggested to be sensitive to the maximum pressure and therefore, a maximum pressure should be built up to as high as the formation can hold. In the subsequent cycles, injecting N2 as a chasing gas flowing CO2 slug has great potential to significantly improve the cycle performance while reducing the CO2 utilization. The optimal operation should have three cycles and the ultimate RF for these three cycles could reach above 30%. The observations of this study suggest that the CO2 huff ‘n’ puff process is a viable technique to enhance light oil recovery in low-pressure tight reservoirs.
Kamy Sepehrnoori - One of the best experts on this subject based on the ideXlab platform.
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optimization of huff n puff field gas enhanced oil recovery through a vertical well with multiple fractures in a low permeability shale sand carbonate reservoir
Energy & Fuels, 2020Co-Authors: Adi Junira, Kamy Sepehrnoori, Steven Biancardi, Raymond Joseph Ambrose, Reza GanjdaneshAbstract:This study aims at identifying some of the potential contributors to increase oil recovery through field gas huff-n-puff in a thick, heterogeneously layered, and low-permeability shale–sand–carbona...
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performance evaluation of co2 huff n puff and continuous co2 injection in tight oil reservoirs
Energy, 2017Co-Authors: Pavel Zuloaga, Jijun Miao, Wei Yu, Kamy SepehrnooriAbstract:The CO2-enhanced oil recovery (EOR) effectiveness was simulated and analyzed by comparing Huff-n-Puff and continuous injection scenarios. A field-scale numerical compositional reservoir model was built based on typical fluid, reservoir, and fracture properties from the Middle Bakken Formation. The effect of matrix permeability ranging from 0.001 mD to 0.1 mD on the comparison of well performance of these two scenarios was investigated. A critical value of permeability was identified. When the permeability is lower than 0.03 mD, the CO2 Huff-n-Puff performs better than the continuous CO2 injection. Subsequently, experiment design and response surface methodology was used to perform sensitivity studies with four uncertain parameters including matrix permeability, number of wells, well pattern, and fracture half-length. The results show that the matrix permeability is the most significant parameter, followed by well pattern and the interaction between fracture half-length and number of wells. Furthermore, three diagnostic contour plots corresponding to 4, 6, and 8 horizontal wells per square mile were generated. Based on these plots, it is convenient to identify the best zone with better CO2-EOR effectiveness for different CO2 injection scenarios. This study can provide a very useful tool for a better understanding of CO2-EOR strategy determination in tight oil reservoirs.
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CO2 injection for enhanced oil recovery in Bakken tight oil reservoirs
Fuel, 2015Co-Authors: Hamid R. Lashgari, Kamy SepehrnooriAbstract:The combination of horizontal drilling and multi-stage hydraulic fracturing have boosted the oil production from Bakken tight oil reservoirs. However, the primary oil recovery factor is very low due to the extremely tight formation, resulting in substantial volumes of oil still remaining in place. Hence, it is important to investigate the potential of applying enhanced oil recovery methods to increase oil recovery in the Bakken formation. Although carbon dioxide (CO2) is widely used in conventional reservoirs to improve oil recovery, it is a new subject and not well-understood in unconventional oil reservoirs such as the Bakken formation. In this paper, we use numerical reservoir simulation to model CO2 injection as a huff-n-puff process with typical reservoir and fracture properties from the Bakken formation. Effects of CO2 molecular diffusion, number of cycle, fracture half-length, permeability and reservoir heterogeneity on the well performance of CO2 huff-n-puff are examined in detail. The results show that the CO2 diffusion plays a significant role in improving oil recovery from tight oil reservoirs, which cannot be neglected in the reservoir simulation model. Additionally, the tight oil formation with lower permeability, longer fracture half-length, and more heterogeneity is more favorable for the CO2 huff-n-puff process. This work can provide a better understanding of the physical mechanisms and key parameters affecting the effectiveness of CO2 injection for enhanced oil recovery in the Bakken formation.
Brij B Maini - One of the best experts on this subject based on the ideXlab platform.
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enhanced heavy oil recovery in thin reservoirs using foamy oil assisted methane huff n puff method
Fuel, 2015Co-Authors: Mingzhe Dong, Xiaofei Sun, Yanyu Zhang, Brij B MainiAbstract:Abstract A considerable portion of heavy oil resides in thin formations. In such reservoir environments, thermal recovery methods tend to be neither effective nor economical, due to significant heat loss and water resource requirements. The methane huff-n-puff process for enhancing heavy oil recovery in thin formations is an alternative that has the advantages of availability of resources and economic efficiency. However, the principal problem with such a process is the high mobility of the gas phase, relative to the oil phase, during the production cycle. In order to overcome this limitation, this paper presents a new enhanced methane injection technique, called the foamy oil-assisted methane huff-n-puff method (FOAM H-n-P). In this process, an oil-soluble foaming agent and methane are injected in a cyclic manner, but in two separate slugs. The methane provides the solution gas drive energy, and the presence of the foaming agent promotes the formation of an in situ foamy oil by trapping the released gas, which significantly enhances the effectiveness of the solution gas drive mechanism. A new experimental procedure was developed to prove that the selected foaming agent has an effective foaminess in conventional heavy oil, and to investigate, quantitatively, the effects of various process parameters on foamy oil stability in the FOAM H-n-P process. A series of experiments were conducted to evaluate FOAM H-n-P performance and to examine the effect of various foaming agent injection parameters on oil recovery. The experimental results show that foaming oil stability increases with greater foaming agent concentration, greater initial heavy oil height, a higher degree of gas bubble dispersiveness, and smaller dispersed gas bubble size. The FOAM H-n-P process can substantially improve heavy oil recovery performance. The most efficient case increases oil recovery by 43.29% OOIP, compared to the traditional methane huff-n-puff process. The above knowledge will have significant importance for the development of heavy oil resources in thin reservoirs.
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enhanced cyclic solvent process ecsp for heavy oil and bitumen recovery in thin reservoirs
Energy & Fuels, 2012Co-Authors: Benyamin Yadali Jamaloei, Mingzhe Dong, Nader Mahinpey, Brij B MainiAbstract:Appropriate techniques have to be developed for improving heavy oil recovery from thin reservoirs in western Canada, where thermal methods suffer from heat loss to overburden/underburden and vapor extraction (VAPEX) is not effective because of the lack of efficient gravity drainage. Considering this, a hydrocarbon gas injection process in huff-n-puff mode, i.e., traditional hydrocarbon-based cyclic solvent process (CSP), has been tested to evaluate its applicability to such thin reservoirs. In the first part of this study, the behavior of methane huff-n-puff for heavy oil recovery is investigated by conducting a series of CSP cycles in a sandpack saturated with crude oil (with a viscosity of 1080.6 cP at 22 °C) and brine. The results of the six methane CSP cycles revealed that methane huff-n-puff is inefficient. The problem is that, during the production cycles, the reservoir pressure has to be greatly reduced to realize solvent gas drive. In doing this, the oil regains its high viscosity, because a large...
Zhaoyang Chen - One of the best experts on this subject based on the ideXlab platform.
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gas production from methane hydrate in a pilot scale hydrate simulator using the huff and puff method by experimental and numerical studies
Energy & Fuels, 2012Co-Authors: Bo Yang, Yu Zhang, Zhaoyang ChenAbstract:A novel three-dimensional 117.8-L pressure vessel, which is called a Pilot-Scale Hydrate Simulator (PHS), is developed to investigate the gas production performance from hydrate-bearing porous media using the huff and puff method through both experimental and numerical simulations. The methane gas and deionized water are injected into the pressure vessel to synthesize methane hydrate. The grain sizes of the quartz sand in the vessel are between 300 and 450 μm. The huff and puff stages, including the injection, the soaking, and the production, are employed for hydrate dissociation. A single vertical well at the axis of the PHS is used as the injection and production well. The whole experiment consists of 15 huff and puff cycles. The numerical simulation results agree well with the experiment. Both the experimental and numerical simulation results indicate that the injected water is mainly restricted around the well during the injection stage. The system pressure fluctuates regularly in each cycle, and the ...
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experimental study on gas production from methane hydrate in porous media by huff and puff method in pilot scale hydrate simulator
Fuel, 2012Co-Authors: Bo Yang, Yu Zhang, Zhaoyang ChenAbstract:Abstract Pilot-Scale Hydrate Simulator (PHS), a novel three-dimensional 117.8-L pressure vessel was developed to investigate the gas production from methane hydrate in porous media using the huff and puff method. In situ methane hydrate was synthesized in the pressure vessel with methane gas and deionized water in quartz sand with grain sizes between 300 and 450 μm. In the PHS, a 9-spot distribution of vertical wells, a single horizontal well and 49-spot distributions of the thermometers and resistance ports are respectively placed in three horizontal layers, which equally divide the vessel into four parts. During the experiment, the huff and puff stages, including the injection, the soaking and the production, are carried out for hydrate dissociation. A vertical well at the axis of the PHS was used as the injection and production well. The initial hydrate saturation before dissociation is 33.66% in volume, and the percentage of the hydrate dissociated could be approximately 94% after 15 huff and puff cycles. The experimental results indicate that with the constant hot water injection rate, the range of the thermal diffusion is restricted around the well, and depressurization rather than thermal stimulation is dominant for gas production. The decline of the cumulative gas produced during each cycle and the diminishing uptrend of the percentage of the hydrate dissociated indicate that the hydrate dissociation rate decreases over time. The gas production efficiency is improved by prolonging the hot water injection time, while this enhancement is limited by the stronger pressurization effect.
